1. Field of the Invention
This invention relates to the field of well logging, and more particularly to measurements of electrical conductivity of earth formations penetrated by a wellbore. More particularly, the invention relates to conductivity measuring instruments which are azimuthally sensitive.
2. Background of the Art
Measurements of selected properties of earth formations penetrated by a wellbore are typically recorded with respect to the depth within the borehole at which they are made. The records are commonly referred to as. xe2x80x9cwell logsxe2x80x9d. Properties of interest of the earth formations are derived from acoustic, electromagnetic, nuclear and other types of measurements. The measurements are typically obtained by conveying a measuring instrument or xe2x80x9csondexe2x80x9d along the wellbore by attaching the instrument to one end of an electrical cable (xe2x80x9cwirelinexe2x80x9d) and extending and retracting the cable by means of a winch or other spooling device located at the surface of the earth. Using the electrical cable as the means for instrument conveyance, the measurements of the formation properties are obtained subsequent to the drilling of the wellbore.
Various drilling parameters such as weight and torque on a drill bit used to drill the wellbore are typically measured during the actual drilling of the wellbore. In addition, formation properties, such as those previously described that are made by wireline conveyed instruments, are also measured during the drilling process rather than subsequent to drilling as in wireline logging operations. These techniques are usually referred to as measurement-while-drilling (MWD) and logging-while-drilling (LWD), respectively.
Drilling techniques known in the art include drilling wellbores from a selected geographic position at the earth""s surface, along a selected trajectory. The trajectory may extend to other selected geographic positions at particular depths within the wellbore. These techniques are known collectively as xe2x80x9cdirectional drillingxe2x80x9d techniques. One application of directional drilling is the drilling of highly deviated (with respect to vertical), or even horizontal, wellbores within and along relatively thin hydrocarbon-bearing earth formations (called xe2x80x9cpay zonesxe2x80x9d) over extended distances. These highly deviated wellbores are intended to greatly increase the hydrocarbon drainage from the pay zone as compared to xe2x80x9cconventionalxe2x80x9d wellbores which xe2x80x9cverticallyxe2x80x9d (substantially perpendicularly to the layering of the formation) penetrate the pay zone.
In highly deviated or horizontal wellbore drilling within a pay zone, it is important to maintain the trajectory of the wellbore so that it remains within a particular position in the pay zone. Directional drilling systems are well known in the art which use xe2x80x9cmud motorsxe2x80x9d and xe2x80x9cbent subsxe2x80x9d as means for controlling the trajectory of a wellbore with respect to geographic references, such as magnetic north and earth""s gravity (vertical). Layering of the formations, however, may be such that the pay zone does not lie along a predictable trajectory at geographic positions distant from the surface location of the wellbore. Typically the wellbore operator uses information (such as LWD logs) obtained during wellbore drilling to maintain the trajectory of the wellbore within the pay zone, and to further verify that the wellbore is, in fact, being drilled within the pay zone. Techniques known in the art for maintaining trajectory are described for example in, R. Fagin et al, MWD resistivity tool guides bit horizontally in thin bed, Oil and Gas Journal, Dec. 9, 1991. The technique described in this reference is based upon LWD conductivity sensor responses. If, as an example, the conductivity of the pay zone is known prior to penetration by the wellbore, and if the conductivities of overlying and underlying zones provide a significant contrast with respect to the pay zone, a measure of formation conductivity made while drilling can be used as a criterion for xe2x80x9csteeringxe2x80x9d the wellbore to remain within the pay zone. More specifically, if the measured conductivity deviates significantly from the conductivity of the pay zone, this is an indication that the wellbore is approaching, or has even penetrated, the interface of the overlying or underlying earth formation. As an example, the conductivity of an oil-saturated sand may be significantly lower than that of a typical overlying and underlying shale. An indication that the conductivity adjacent the wellbore is increasing can be interpreted to mean that the wellbore is approaching the overlying or the underlying formation layer (shale in this example). The technique of directional drilling using a formation property measurement as a guide to trajectory adjustment is generally referred to as xe2x80x9cgeosteeringxe2x80x9d.
In addition to electromagnetic measurements, acoustic and radioactive measurements are also used as means for geosteering. Again using the example of an oil producing zone with overlying and underlying shale, natural gamma radioactivity in the pay zone is generally considerably less than the natural gamma ray activity of the shale formations above and below the pay zone. As a result, an increase in the measured natural gamma ray activity from a LWD gamma ray sensor will indicate that the wellbore is deviating from the center of the pay zone and is approaching or even penetrating either the upper or lower shale interface.
If, as in the prior examples, the conductivity and natural radioactivity of the overlying and underlying shale formations are similar to each other, the previously described geosteering techniques indicate only that the wellbore is leaving the pay zone, but do not indicate whether the wellbore is diverting out of the pay zone through the top of the zone or through the bottom of the zone. This presents a problem to the wellbore operator, who must correct the wellbore trajectory to maintain the selected position in the pay zone.
Electromagnetic induction logging instruments used in wireline logging techniques are well known in the art for determining conductivity of formations surrounding the wellbore. See for example, U.S. Pat. No. 4,651,101 issued to Barber et al, U.S. Pat. No. 4,873,488 issued to Barber et al and U.S. Pat. No. 5,688,475 issued to Orban et al. The instruments described in these patents, generally speaking, include a transmitter coil and an array of receiver coil pairs disposed at selected positions along the instrument. Each receiver coil pair includes a main receiver coil and a xe2x80x9cbuckingxe2x80x9d coil electrically connected to the main receiver coil. In general, the transmitter and receiver coils are in the form of magnetic dipoles having their axes substantially coaxial with the instrument axis (referred hereinafter as axial magnetic dipoles xe2x80x9cAMDxe2x80x9d).
Electromagnetic induction well logging instruments are well suited for geosteering applications because their lateral (radial) depth of investigation into the formations surrounding the wellbore is relatively large, especially when compared to nuclear and acoustic instruments. The deeper radial investigation enables induction instruments to xe2x80x9cseexe2x80x9d a significant lateral (or radial) distance from axis of the wellbore. In geosteering applications, this larger depth of investigation would make possible detection of approaching formation layer boundaries at greater lateral distances from the wellbore, which would provide the wellbore operator additional time to make any necessary trajectory corrections. However, induction logging instruments are capable of resolving axial and lateral (radial) variations in conductivity of the formations surrounding the instrument, but the response of these instruments generally cannot resolve azimuthal variations in the conductivity of the formations surrounding the instrument. A limitation on geosteering ability which results from this limitation of induction logging instruments will be further explained.
A well logging instrument which provides directionally sensitive measurements would give valuable information in directional drilling and geosteering. Directional electromagnetic induction instruments having transmitter and receiver coils tilted relative to the instrument axis are being studied. One example of such an instrument is described, for example in U.S. Pat. No. 5,508,616 issued to Sato et al. The instrument described in the Sato et al patent includes transmitter coils and receiver coils inclined with respect to the instrument axis at about 30 degrees. This coil arrangement provides some degree of azimuthal sensitivity to the measurements.
More general, xe2x80x9ctriaxialxe2x80x9d induction tools which have directionally (including azimuthally) sensitive response are disclosed in U.S. Pat. No. 3,609,521, xe2x80x9cElectromagnetic Logging Device and Method Utilizing Three Mutually perpendicular Coils for Determining the Dip of Discontinuities in the Electrical resistivity of Underground Formationsxe2x80x9d issued to Desbrandes, U.S. Pat. No. 3,808,520 xe2x80x9cTriple Coil Induction Logging Method for Determining Dip, Anisotropy and True Resistivityxe2x80x9d issued to Runge, U.S. Pat. No. 4,302,722 xe2x80x9cInduction Logging Utilizing Resistivity and Reactivity Induced Signal Components to Determine Conductivity and Coefficient of Anisotropyxe2x80x9d issued to Gianzero, U.S. Pat. No. 4,302,723 xe2x80x9cApparatus and Method for determining Dip and/or Anisotropy of Formations Surrounding a Boreholexe2x80x9d issued to Moran, U.S. Pat. No. 4,360,777 xe2x80x9cInduction Dipmeter Apparatus and Methodxe2x80x9d issued to Segesman, U.S. Pat. No. 4,980,643 xe2x80x9cInduction Logging Apparatus Utilizing Skew Signal Measurements in Dipping Bedsxe2x80x9d issued to Gianzero et al, and U.S. Pat. No. 5,442,294 xe2x80x9cConductivity Method and Apparatus for Measuring Strata Resistivity Adjacent a Boreholexe2x80x9d issued to Rorden. Although some of these prior art disclosures show electromagnetic induction instruments having directionally sensitive response, electromagnetic induction measurements using coils oriented other than parallel to the instrument axis have proven difficult to make and use because they are of extremely sensitivity to conditions in the wellbore itself. Various configurations of transmitters and receivers of these prior art instruments are shown in FIG. 1. For example, the conventional axial magnetic dipole arrangement is identified as AMD in FIG. 1. The instrument having coils at oblique (30 degree) angles is shown as TILT in FIG. 1. A transverse magnetic dipole instrument is shown as TMD, and a cross-dipole arrangement is shown as CROSS. The various arrangements shown in FIG. 1 indicate the principal magnetic moment direction of the various transmitters and receivers on each such instrument The transmitters of the TILT, TMD, and CROSS arrangements have a magnetic dipole component which is oblique and/or perpendicular to the axis of the instrument, which results in significant axial flow of current in the wellbore. Measurements of this type are therefore highly sensitive to conditions in the borehole, in particular to decentralization of the instrument in the borehole. According to J. H. Moran, and S. Gianzero, in Effects of Formation Anisotropy on Resistivity-Logging Measurements, Geophysics, vol. 44, No. 7, July 1979, pp. 1266-1286, xe2x80x9cwith horizontal magnetic dipoles, in practice formation and borehole heterogeneities will pose significant difficulties . . . Borehole effects probably make such a tool impractical.xe2x80x9d
The desirability of being able to directionally resolve the resistivity of earth formations is illustrated in FIGS. 2a and 2b. In FIG. 2a a pay zone, or target zone, is shown at 16. It is desired, in this example, that the trajectory of a wellbore 10 is maintained within the target zone 16. Zones above 12 and zones below 14 the target 16 can be shale or any other formation which is not economically productive. In the example of FIG. 2a, the upper boundary 15 and lower boundary 17, respectively, between the target zone 16 and the zone above 12 and zone below 14 divert upward in the general direction of the wellbore 10 trajectory. An opposite diversion of the zone above and zone below is shown in FIG. 2b. Conventional electromagnetic induction measuring devices (and most LWD resistivity sensors known in the art) respond to the change in overall conductivity around the wellbore 10 as the wellbore approaches, and then penetrates one of the shale zones (either 14 in FIG. 2a or 12 in FIG. 2b), but such conventional induction resistivity measuring devices are unable to resolve which of the zones (either 14 in FIG. 2a or 12 in FIG. 2b) is actually being approached or penetrated by the wellbore if the induction instrument responses of the zones 14, 12 are similar.
U.S. Pat. No. 5,467,832 to Orban et al discloses a method for directionally drilling a wellbore which uses a MWD subsection or xe2x80x9csubxe2x80x9d which is positioned within a drill string in the immediate vicinity of the drill bit. The sub includes instrumentation which makes various measurements such as the inclination of the borehole proximate to the drill bit, the gamma ray emission from the earth formations surrounding the sub, the electrical resistivity (inverse of conductivity) of the formations surrounding the sub, and a selected drilling performance parameters. The formation measurements are used to verify that the wellbore is disposed within the formation of interest (which may be a pay zone). The sensors and measurements from the instrument shown in the Orban et al patent cannot, however, be used to determine if the wellbore is approaching the upper boundary of the zone of interest, or the lower boundary of the zone of interest if the characteristics of the overlying and underlying formations are similar.
U.S. Pat. No. 5,594,343 issued to Clark et al discloses a well logging apparatus and methods for determining electromagnetic properties of earth formations penetrated by a wellbore. The instrument described in the Clark et al ""343 patent includes a plurality of transmitters, with the transmitters being asymmetrically disposed about a pair of receiving antennas. This transducer arrangement provides measurements with different lateral depths of investigation which can be used at least in part to compensate for the effects of the borehole on the measurements. Those transmitter-receiver arrangements do not have azimuthal directionality, and no methodology is disclosed in the Clark et al patent for determining the position of the instrument within a zone with respect to the overlying and underlying formations.
U.S. Pat. No. 4,785,247 issued to Meador discloses an apparatus for measuring formation conductivity while drilling. The apparatus of the Meador ""247 patent includes coils arranged in a wall of a drill collar. One embodiment of the apparatus in the Meador patent includes transmitter and receiver coils disposed in a wall substantially on one side of the collar. The arrangement of coils shown in the Meador patent may provide measurements having some degree of azimuthal sensitivity, but this instrument has not been shown to be capable of assisting a wellbore operator in determining azimuthal distribution of conductivity surrounding the wellbore.
An example of an instrument which includes resistivity sensors which can resolve azimuthal variations in conductivity (or resistivity) surrounding the wellbore is described in U.S. Pat. No. 6,023,168 issued to Minerbo and assigned to the assignee of this invention. The instrument described in the Minerbo ""168 patent generally makes a set of xe2x80x9cgalvanicxe2x80x9d measurements around the circumference of the instrument at a selected axial position along the instrument. While this instrument can resolve azimuthal variations in resistivity or conductivity, the depth of investigation of this instrument is relatively limited, which would make this instrument less desirable for use in geosteering. Another limitation of the instrument in the Minerbo ""168 patent is that it does not work in drilling fluids which are not electrically conductive (known in the art by such terms as xe2x80x9coil base mudxe2x80x9d)
Another instrument which can resolve azimuthal variations in resistivity is described, for example in U.S. Pat. No. 5,339,036 issued to Clark et al. The instrument described in the Clark et al ""036 patent is suitable for use while a wellbore is being drilled. This instrument, when combined with suitable rotary orientation measuring devices, as would be used in a typical measurement while drilling (MWD) apparatus, can make resistivity measurements related to the azimuthal orientation of formations surrounding a wellbore. As is the case for the instrument in Minerbo ""168, the instrument in Clark et al ""036 makes galvanic resistivity measurements, which may have limited lateral investigation capability and may not work in non-conductive drilling fluids.
Techniques for using some of the foregoing resistivity measuring devices for geosteering are described, for example, in Innovative Use of BHAs and LWD Measurements to Optimize Placement of Horizontal Laterals, G. Farruggio et al, SPE/IADC paper no. 52825, Society of Petroleum Engineers, Richardson, Tex. (1999).
Other azimuthally sensitive resistivity measuring instruments are described in U.S. Pat. No. 5,892,460 issued to Jerabek et al, U.S. Pat. No. 5,442,294 issued to Rorden and U.S. Pat. No. 5,530,358 issued to Wisler et al. All of these references describe antenna configurations which can be used in LWD apparatus.
One aspect of the invention is an induction logging instrument is which includes at least one induction transmitter arranged as an axial magnetic dipole, and at least one differential axial magnetic dipole (xe2x80x9cDAMDxe2x80x9d) receiver disposed at a selected axial distance from the at least one induction transmitter.
In one embodiment, the DAMD receiver includes a pair of coils. Each coil in the pair is wound on an axis substantially parallel to the axis of the instrument. Each of the coil axes is displaced from the instrument axis by a substantially equal lateral distance, and in opposed directions with respect to each other about the instrument axis. Each coil of the pair of coils is disposed at substantially the same axial position along the instrument, and the coils are connected to circuits adapted to determine a difference between signals induced in each of the coils.
In another embodiment, the DAMD receiver includes two pairs of coils, each wound on an axis substantially parallel to the axis of the instrument. Each of the coil axes in each pair is displaced from the instrument axis by a substantially equal lateral distance in opposed directions. The pairs are substantially orthogonal to each other. Each of the coils is disposed at substantially the same axial position along the instrument, and the coils in each pair are connected to circuits adapted to determine a difference between signals induced in each of the coils.
In another exemplary embodiment, the DAMD receiver includes two pairs of coils positioned similarly to the laterally displaced coils in any of the foregoing embodiments. Each pair of coils is disposed at a different axial spacing from the transmitter coil. Each pair of substantially equally displaced coils is connected to circuits which determine a difference in signal between the coils. The number of turns in each coil is selected to produce a condition of xe2x80x9cmutual balance.xe2x80x9d
Another embodiment includes, in addition to any of the foregoing, an array of DAMD receivers each positioned at a selected axial spacing from the transmitter.
Another embodiment includes a conventional AMD induction transmitter, and at least one conventional axial magnetic dipole (xe2x80x9cAMDxe2x80x9d) receiver along with the one or more DAMD receivers.
Yet another embodiment includes an AMD induction transmitter, an array of AMD receivers and one or more DAMD receivers.
All the foregoing embodiments may have as alternatives the substitution of one or more DAMD transmitters for the AMD transmitter. In a particular example of this embodiment, the induction logging instrument includes at least on AMD transmitter, at least one DAMD transmitter, and an array of AMD receivers. When the AMD transmitter is energized, the receivers detect conventional AMD signals. When the DAMD transmitter is energized, the receivers detect DAMD signals.
Other aspects and advantages of the invention will be apparent from the description which follows.